Field of the Disclosure
Embodiments of this disclosure generally relate to stimulation fluids.
Description of the Related Art
Fracture treatments are utilized to stimulate and improve fluid conductivity between a wellbore and a formation of interest to increase fluid production rate and associated reserves. Hydraulic fracture treatments are typically used in low-permeability formations, in conventional reservoirs to bypass near-wellbore permeability damage, and in unconventional reservoirs to intersect induced fractures with a natural fracture network.
Hydraulic stimulation fluids have been classified into different fluid types, including:                Conventional, comprised of a gelling agent and crosslinker(s);        Water Frac, (sometimes referred to as “slick water”) comprised of a friction reducer, gelling agent, and/or a viscoelastic surfactant;        Hybrid, comprised of a combination of friction reducer, gelling agent, and crosslinker(s);        Energized, incorporating carbon dioxide or nitrogen into the fluid;        Acid Frac, comprised of a gelled acid base; and        Gas Frac, comprised of a gas, normally propane as the base fluid.        
A typical treatment injects a viscous stimulation fluid to open a fracture of a desired geometry, and the viscous stimulation fluid carries a proppant into the opened fracture to maintain conductivity in the fracture after the treatment is completed. Viscous stimulation fluids may have features that damage the permeability of the proppant pack and/or the formation near the fracture. For example, water-based stimulation fluids may imbibe into the formation face and reduce permeability by e.g. capillary forces, may precipitate scale, and may cause fines migration during well flow back and clean-up.
Recent data suggests that approximately 98% of the hydraulic fracture stimulations in the U.S. utilize water-based technology. Minimizing or eliminating water and the associated water-based chemicals (such as acids, biocides, corrosion inhibitors, oxygen scavengers, friction reducers, crosslinkers, breakers, and certain gelling agents) from the base fluid would help reduce the environmental footprint and certain chemical costs associated with fracing.
Water-based frac fluids also have associated disposal and or clean-up issues and may have usage conflicts. Use of water for hydraulic fracturing can divert water from stream flow, water supplies for municipalities and industries such as power generation, as well as recreation and aquatic life. After a fracture treatment, frac fluid that flows back to the surface must be disposed of or remediated, and the more fluid that is utilized in the treatment the greater the disposal risk and expense. The large volumes of water required for most common hydraulic fracturing methods have raised concerns for arid regions particularly in drought-prone Texas. Frac water disposal via injection into deep underground wells has been associated with recent increases in seismicity in Central Oklahoma.
Massive hydraulic fracturing uses traditionally between 1.2 and 3.5 million US gallons of water per well, with large projects using more than 5 million US gallons. Each treatment is comprised of a series of stages. Certain unconventional horizontal wells may have up to 40 or more stages. Each stage may utilize more than 300,000 gallons of water and more than 5.5 million pounds of proppant.
Multi-well pad drilling or the ability to drill and complete multiple wells on a single pad is becoming prevalent in the industry because of the small footprint and increased operational efficiency. This technology is affecting the hydraulic fracturing industry as six or more individual well stimulations may be conducted sequentially from a single pad. Complementing this technology is a process known as “zipper fracs” that involves alternating frac stimulations between two offsetting wells whose wellheads are located on the same pad. When combined, these technologies place additional logistical requirements on the fracing operator.
Acid fracturing treatments are utilized to remove damage and/or open channels in the formation. The acid etches channels that, in theory, remain open after the hydraulic pressure is released and the formation relaxes back to a naturally pressured condition. It is desirable that the acid flow into and etch or remove damage from areas of the formation that do not flow well before the treatment. However, the highly permeable and naturally fractured areas of the formation tend to accept fluid better and thereby take more of the acid than is desired. Therefore, fluid loss and diverting additives may be added to the acid fracturing treatment to block the high permeability channels and redirect the treatment into lower permeability channels.
Foam fracturing is also a standard method used in North America to stimulate low-permeability or partially pressured depleted reservoirs including unconventional shale and coal seams. Foam based frac fluids can be attractive due to the low water content as the foam typically consists of a high percentage of a gas, typically carbon dioxide or nitrogen, as the internal phase and a lesser percentage of a liquid as the external phase that includes a stabilizing surfactant called a foaming agent. Foams at nitrogen qualities of 70 to 90 percent have been applied effectively in the formation types mentioned above. High quality foams require less water but may lack sufficient viscosity to support the necessary proppant load.
Liquefied petroleum gas (“LPG”), primarily propane gel, has been used as a hydrocarbon frac fluid that is non-damaging to the formation. Its properties include: low surface tension, low viscosity, low-density, along with miscibility with naturally occurring reservoir hydrocarbons. This waterless method increases initial production rates, helping establish production much sooner than traditional fracturing methods. It is also able to recover the majority of the fracturing fluid within a few days of the stimulation which create economic and environmental benefits of a quick clean-up with minimal waste and disposal. However, the cost and availability of large quantities of propane required for multi-stage pad stimulations is sometimes a deterrent to the using this technology.
Therefore, there is a need for new stimulation fluids that are non-damaging to the formation, have minimal water content and chemical additions, are naturally occurring and locally available components, have fast clean-up, are cost effective, and are totally recoverable with minimal proppant flow back.